Note: Descriptions are shown in the official language in which they were submitted.
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METHOD AND APPARATUS FOR MANAGING VARIABLE DENSITY
DRILLING MUD
CROSS REFERENCE TO RELATED APPLICATIONS
This application claims the benefit of U. S. Provisional Application No.
601779,679,
filed 6 March 2006.
FIELD OF THE INVENTION
[0001] This invention relates generally to an apparatus and method for use in
wellbores and associated with drilling operations to produce hydrocarbons.
More
particularly, this invention relates to a wellbore apparatus and method for
managing
compressible particles in a variable density drilling mud.
BACKGROUND
[0002] This section is intended to introduce various aspects of the art, which
may be associated with exemplary embodiments of the present invention. This
discussion is believed to assist in providing a framework to facilitate a
better
understanding of particular aspects of the present invention. Accordingly, it
should
be understood that this section should be read in this light, and not
necessarily as
admissions of prior art.
[0003] The production of hydrocarbons, such as oil and gas, has been
performed for numerous years. To produce these hydrocarbons, a weilbore is
typically drilled in intervals with different casing strings installed to
reach a
subsurface formation. The casing strings are installed in the weilbore to
prevent the
collapse of the wellbore walls, to prevent undesired outflow of drilling mud
into the
formation, and/or to prevent the inflow of formation fluid into the wellbore.
Because
the casing strings for lower intervals pass through already installed-casing
strings,
the casing strings are formed in a nested configuration that continue to
decrease in
diameter in each of the subsequent intervals of the wellbore. That is,
typically casing
strings in the lower intervals have smaller diameters to fit within the
previously
installed casing strings. Alternatively, the expandable casing strings may be
utilized
within the wellbore. However, the expandable casing strings are typically more
expensive and increase the cost of the well.
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[0004] The process of installing casing strings involves tripping/running the
casing string and cementing the casing string, which is time consuming and
costly.
With the nested configuration, the initial casing strings have to be
sufficiently large to
provide a weElbore diameter that is able to be utilized for the tools and
other devices.
With subsurface formations being located at greater depths, the diameter of
the
initial casing strings are relatively large to provide a final wellbore
diameter useable
for the production of hydrocarbons. Large wellbores increase the cost of the
drilling
operations because the increased size results in increased cuttings, increased
casing string size and costs, and increased volume of cement and drilling mud
utilized in the wellbore.
[0005] Accordingly, various processes are utilized to reduce the diameter of
casing strings installed within the wellbore. For example, some processes
describe
modifying the drilling mud to install fewer different casing strings within
the wellbore.
A drilling mud is utilized to remove cuttings and provide hydrostatic pressure
to the
subsurface formation to maintain drilling operations for a well. The weight or
density
of the drilling mud is typically maintained between the pore pressure gradient
(PPG)
and the fracture pressure gradient (FG) for drilling operations. However, the
PPG
and FG often vary along with the true vertical depth (TVD) of the well, which
present
problems for maintaining the weight or density of the drilling mud. If the
density of
the drilling mud is below the PPG, the well may kick. A kick is an influx of
formation
fluid into the wellbore, which has to be controlled before drilling operations
may
resume. Also, if the density of the drilling mud is above the FG, the drilling
mud may
be leaked off into the formation. The leakage may result in lost returns or
large
volumes of drilling mud loss, which has to be replaced for the drilling
operations to
resume. Accordingly, the density of the drilling mud has to be maintained
within the
PPG and FG to continue drilling operations that utilize the same size casing
string.
10006] Accordingly, drilling operations may utilize variable density drilling
mud
to maintain the density of the drilling mud within the PPG and FG for the
wellbore.
See Intl. Patent Application Publication No. WO 2006/007347. To reduce the
number of intermediate casing strings utilized within the well, the variable
density
drilling mud may include various compressible particles to provide a drilling
mud that
operates within the PPG and FG. Because the drilling operations may be
continuous, the compressible particles may have to circulate within the
wellbore one
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or more times. As such, there is a need for a method and apparatus for
managing
the compressible particles that are utilized within the variable density
drilling mud.
[0007] Other related material may be found in at least U.S. Patent No.
3,174,561; U.S. Patent No. 3,231,030; U.S. Patent No. 4,099,583; U.S. Patent
No.
4,192,392; U.S. Patent No. 5,881,826; U.S. Patent No. 5,910,467; U.S. Patent
No.
6,156,708; U.S. Patent No. 6,415,877; U.S. Patent No. 6,422,326; U.S. Patent
No.
6,497,289; U.S. Patent No. 6,530,437; U.S. Patent No. 6,588,501; U.S. Patent
No.
6,739,408; U.S. Patent No. 6,953,097; U.S. Patent Application Publication No.
2004/0089591; U.S. Patent Application Publication No. 2005/0023038; U.S.
Patent
Application Publication No. 2005/0113262; U.S. Patent Application Publication
No.
2005/0161262; and Intl. Patent Application Publication No. WO 2006/007347.
SUMMARY
[0008] In one embodiment, a system for drilling a wellbore is described. The
system includes a wellbore with a variable density drilling mud, drilling
pipe, a bottom
hole assembly disposed in the welibore and a drilling mud processing unit in
fluid
communication with the wellbore. The variable density drilling mud has
compressible
particles and drilling fluid. The bottom hole assembly is coupled to the
drilling pipe,
while the drilling mud processing unit is configured to separate the
compressible
particles from the variable density drilling mud. The compressible particles
in this
embodiment may include compressible hollow objects filled with pressurized gas
and
configured to maintain the mud weight between the fracture pressure gradient
and
the pore pressure gradient.
[0009] The system may also include various modifications to the drilling mud
processing unit. For instance, as a first embodiment, the drilling mud
processing unit
may include a rig shaker screen configured to receive the variable density
drilling
mud and cuttings from the wellbore and divert material equal to or greater
than the
size of the compressible particles to a shaker flow path; a cutting shaker
screen
coupled to the rig shaker screen and configured to divert material equal to or
less
than the size of the compressible particles from the shaker flow path to a
cutting flow
path; a hydrocyclone coupled to the cutting shaker screen and configured to
receive
material from the cutting flow path, separate material from the cutting flow
path
based on density; and provide material having a density similar to the
compressible
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particles to a hydrocyclone flow path; and an additional shaker screen coupled
to the
hydrocyclone and configured to receive material from the hydrocyclone flow
path and
remove the compressible particles from the hydrocyclone flow path.
Alternatively,
material larger than compressible particles may be removed in the rig shaker
screen
and those equal to or smaller than compressible particles may be diverted to a
shaker flow path. Then, the next separation diverts material equal to or
greater than
the compressible particles to a cutting flow path provided to the
hydrocyclones.
[0010] As a second embodiment, the drilling mud processing unit may
include a rig shaker screen that receives the variable density drilling mud
and
cuttings from the wellbore and removes the cuttings greater than the size of
the
compressible particles; and a settling tank in fluid communication with the
rig shaker
screen and configured to receive the remaining material from the rig shaker
screen
and separate compressible particles from the remaining material by density.
This
drilling mud processing unit may also include an additional shaker screen
coupled to
the settling tank and configured to remove the compressible particles from the
remaining material. As a third embodiment, the drilling mud processing unit
may
include a rig shaker screen configured to receive the variable density
drilling mud
and cuttings from the wellbore and divert material less than or equal to the
size of
the compressible particles to a shaker flow path; a hydrocyclone coupled to
the rig
shaker screen and configured to receive the shaker flow path and divert
material
having a density similar to the density of the compressible particles to a
hydrocyclone flow path; and an additional shaker screen coupled to the
hydrocyclone
and configured to receive the hydrocyclone flow path and remove the
compressible
particles from the hydrocyclone flow path. As a fourth embodiment, the
driiling mud
processing unit may include a rig shaker screen configured to receive the
variable
density drilling mud and cuttings from the wellbore and divert material equal
to or
less than the size of the compressible particles into a shaker flow path; a
centrifuge
coupled to the rig shaker screen and configured to receive the shaker flow
path and
divert material having a density similar to the compressible particles into a
centrifuge
flow path; and an additional shaker screen coupled to the centrifuge and
configured
to receive the centrifuge flow path and remove the compressible particles from
the
centrifuge flow path.
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[0011] Further, the drilling mud processing unit may include different
embodiments to insert the compressible particles into the drilling fluid to
form the
variable density drilling mud. For example, as a first embodiment, the
drilling mud
processing unit may include a mud pit; at least one mixer in fluid
communication with
the mud pit and configured to blend the compressible particles with the
drilling fluid
to form the variable density drilling mud; at least one monitor in fluid
communication
with the mud pit and configured to monitor the density of the variable density
drilling
mud; and a mud pump in fluid communication with the monitor and configured to
provide the variable density drilling mud to the wellbore. As a second
embodiment,
the drilling mud processing unit may include a mud pit; at least one monitor
in fluid
communication with the mud pit and configured to combine the compressible
particles with the drilling fluid to form the variable density drilling mud;
and a mud
pump in fluid communication with the at least one monitor and configured to
provide
the variable density drilling mud to the wellbore. As a third embodiment, the
drilling
mud processing unit may include a storage vessel configured to receive
drilling fluid
and compressible particles to form the variable density drilling mud; a
compression
pump in fluid communication with the storage vessel and configured to compress
the
compressible particles in the variable density drilling mud into the
compressed state;
and a mud pump in fluid communication with the compression pump via piping and
configured to provide the variable density drilling mud to the wellbore. As a
fourth
embodiment, the drilling mud processing unit may include a compressible
particles
pump configured to provide the compressible particles to a primary flow path
in the
wellbore; and a drilling fluid pump configured to provide the drilling fluid
to a
secondary flow path in the wellbore, wherein the compressible particles and
the
drilling fluid mix in a blending section of the wellbore. As a fifth
embodiment, the
drilling mud processing unit may include a compressible particles pump
configured to
pump the compressible particles from the surface to a blending section within
the
wellbore through a parasite string; and a drilling fluid pump configured to
pump the
drilling fluid to a drill bit within the wellbore through the drill pipe,
wherein the
compressible particles and the drilling fluid mix in a blending section of the
wellbore.
[0012] In addition, the bottom hole assembly may be configured to separate
the compressible particles from the variable density drilling mud to divert
the
compressible particles away from a drill bit. As a first embodiment, the
bottom hole
assembly may include a drill bit; a separator coupled between the drill bit
and the drill
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pipe and a separator. The separator may be configured to: receive the variable
density drilling mud; separate the variable density drilling mud into a first
flow path
and a second flow path, wherein at least a portion of the compressible
particles are
within the second flow path; provide the first flow path to a first wellbore
location near
or through the drill bit; and divert the second flow path to a second wellbore
location
above the drill bit. The second flow path may be diverted into a bypass tube
to the
second wellbore location above the drill bit from the center of the separator
or
diverted through a bypass opening to the second weilbore location above the
drill bit
from an exterior wall of the separator. The diverting of the compressible
particles
may be different for different densities of the compressible particles in
certain
applications. Also, the compressible particles may be separated at different
locations
within the wellbore and at the surface.
[0013] 'In a second embodiment, a method associated with production of
hydrocarbons is described. The method includes circulating a variable density
drilling mud in a wellbore, wherein the variable density drilling mud
maintains the
density of a drilling mud between the pore pressure gradient (PPG) and the
fracture
pressure gradient (FG) for drilling operations and comprises compressible
particles
with a drilling fluid; and diverting at least a portion of compressible
particles from the
variable density drilling mud to manage the use of the compressible particles.
Also,
the method may include obtaining compressible particles and drilling fluid and
combining the compressible particles and the drilling fluid to form a variable
density
drilling mud. The compressible particles in this embodiment may include
compressible hollow objects filled with pressurized gas and configured to
maintain
the mud weight between the fracture pressure gradient and the pore pressure
gradient. The method may also include separating the compressible particles
from
the variable density drilling mud within the wellbore at a bottom hole
assembly.
[0014] The method may also include separating damaged compressible
particles from undamaged compressible particles in the variable density
drilling mud;
and recirculating undamaged compressible particles in the variable density
drilling
mud. The separation of the damaged compressible particles from the undamaged
compressible particles may be performed at the surface of the wellbore.
Further, the
separation of the damaged compressible particles from the undamaged
compressible particles may include additional steps of receiving slurry from
the
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wellbore, wherein the slurry comprises cuttings and the variable density
drilling mud;
separating the slurry into a first flow of material greater than the size of
the
compressible particles and a second flow of material less than or equal to the
size of
the compressible particles via screens; providing the second flow to a
hydrocyclone;
and separating undamaged compressible particles from the variable density
drilling
mud, cuttings and damaged compressible particles in the hydrocyclone. As a
second alternative, the separation of the damaged compressible particles from
the
undamaged compressible particles may include providing slurry from the
wellbore to
a settling tank, wherein the slurry comprises cuttings and the variable
density drilling
mud; and separating the undamaged compressible particles from the settling
tank.
As a third alternative, the separation of the damaged compressible particles
from the
undamaged compressible particles may include receiving slurry from the
wellbore,
wherein the slurry comprises cuttings and the variable density drilling mud;
separating the slurry into a first flow of material greater than the size of
the
compressible particles and a second flow of material less than or equal to the
size of
the compressible particles via screens; providing the second flow to a
centrifuge; and
separating undamaged compressible particles from the variable density drilling
mud,
cuttings and damaged compressible particles in the centrifuge. As a fourth
alternative, the separation of the damaged compressible particles from the
undamaged compressible particles may include receiving the variable density
drilling
mud and cuttings from the wellbore; removing material greater than or equal to
the
size of the compressible particles; providing the removed material to a
settling tank
to separate compressible particles from the remaining material by density.
[0015] Further, the combination of the compressible particles and the drilling
fluid may be performed in various embodiments, which are at the surface or
within
the wellbore. For example, the combination of the compressible particles and
the
drilling fluid may include blending the compressible particles with the
drilling fluid to
form the variable density drilling mud in a mud pit; monitoring the density of
the
variable density drilling mud; and pumping the variable density drilling mud
into the
wellbore. As a second embodiment, the combination of the compressible
particles
and the drilling fluid may include blending the compressible particles with
the drilling
fluid in a monitor to form the variable density drilling mud; and pumping the
variable
density drilling mud into the wellbore. As a third embodiment, the combination
of the
compressible particles and the drilling fluid may include blending the
compressible
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particles with the drilling fluid to form the variable density drilling mud in
a storage
vessel; compressing the variable density drilling mud in compression pumps;
and
providing the compressed variable density drilling mud to rig pumps via
piping; and
pumping the compressed variable density drilling mud into the wellbore. As a
fourth
embodiment, the combination of the compressible particles and the drilling
fluid may
include pumping the compressible particles through a primary flow path into
the
wellbore; pumping the drilling fluid through a secondary flow path into the
wellbore;
and blending the compressible particles and drilling fluid in a blending
section of the
wellbore. In this embodiment, the primary flow path may be a parasite string
and
the secondary flow path may be drill pipe or the primary flow path and the
secondary
flow path may be provided from a dual walled drill string.
[0016] In a third embodiment, a method associated with the production of
hydrocarbons is described. The method includes circulating a variable density
drilling mud in a wellbore, wherein the variable density drilling mud
maintains the
density of a drilling mud between the pore pressure gradient (PPG) and the
fracture
pressure gradient (FG) for drilling operations and comprises compressible
particles
with a drilling fluid; diverting at least a portion of compressible particles
from the
variable density drilling mud to manage the use of the compressible particles;
disposing devices and a production tubing string within the wellbore; and
producing
hydrocarbons from the devices via the production tubing string.
[0017] Moreover, in one or more of the embodiments above, a density
monitor may be used to analyze or review compressible particles in the
variable
density drilling mud. For example, in embodiments with a mud pit, one or more
monitors of at least 1 atmosphere density, which may measure density up to a
pressure as high as those experienced in the system, may be used to determine
density responses of variable density drilling mud to various levels of
applied
pressure. That is, the monitors may review or analyze the density behavior as
a
function of pressure and temperature as the variable density drilling mud
enters the
drill string and/or exits the wellbore to determine attrition rates and
provide real-time
estimates of the density/pressure profile within the we{lbore.
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BRIEF DESCRIPTION OF THE DRAWINGS
[0018] The foregoing and other advantages of the present invention may
become apparent upon reviewing the following detailed description and drawings
of
non-limiting examples of embodiments in which:
[0019] FIG. 1 is an illustration of an exemplary drilling system in accordance
with certain aspects of the present techniques;
[0020] FIG. 2 is an exemplary flow chart utilized in the drilling system of
FIG.
1 in accordance with certain aspects of the present techniques;
[0021] FIGs. 3A-3D are exemplary configurations for the removal of
compressible particles in accordance with certain aspects of the present
techniques;
[0022] FIGs. 4A-4E are exemplary configurations for insertion of
compressible particles in accordance with certain aspects of the present
techniques;
and
[0023] FIGs. 5A-5B are exemplary embodiments of a separator for removing
compressible particles downhole in accordance with certain aspects of the
present
techniques; and
[0024] FIG. 6 is an illustration of an exemplary drilling system with downhole
separators to manage the density of the wellbore annulus in accordance with
certain
aspects of the present techniques.
DETAILED DESCRIPTION
[0025] In the following detailed description section, the specific embodiments
of the present invention are described in connection with preferred
embodiments.
However, to the extent that the following description is specific to a
particular
embodiment or a particular use of the present invention, this is intended to
be for
exemplary purposes only and simply provides a description of the exemplary
embodiments. Accordingly, the invention is not limited to the specific
embodiments
described below, but rather, it includes all alternatives, modifications, and
equivalents failing within the true spirit and scope of the appended claims.
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[002fi] The present technique is directed to a method and apparatus for
managing compressible particles utilized with a drilling fluid to provide a
variable
density drilling mud for drilling operations in a well. Because the
compressible
particles may include spheroids, ellipsoids, or the like, a method and
apparatus for
managing these compressible particles during drilling operations may be
beneficial
to maintain the drilling mud density between the pore pressure gradient (PPG)
and
the fracture pressure gradient (FG). Accordingly, drilling operations may
include any
process where surface fluids are used to achieve and maintain a desired
hydrostatic
pressure in a wellbore and/or the processes of circulating this fluid to,
among other
uses, remove formation cuttings from the wellbore. Because compressible
particles
are utilized in the variable density drilling mud, the present techniques
relate to
removal, circulation, and insertion of the compressible particles into the
drilling fluid.
Further, it should be noted that the following methods and procedures are not
limited
to drilling operations, but may also be utilized in completion operations, or
any
processes that use surface stored/prepared fluids having compressible
particles.
[0027] To begin, the present techniques involve the use of compressible
particles and a drilling fluid, which may be referred to as a variable density
drilling
mud. As noted in Intl. Patent Application Publication No. WO 2006/007347,
which is
incorporated by reference, the compressible particles may include compressible
or
collapsible hollow objects of various shapes, such as spheres, cubes,
pyramids,
oblate or prolate spheroids, cylinders, pillows and/or other shapes or
structures.
These compressible hollow objects may be filled with pressurized gas, or even
compressible solid materials or objects. Also, the compressible particles,
which are
selected to achieve a favorable compression in response to pressure changes,
may
include polymer, polymer composites, metals, metal alloys, and/or polymer or
polymer composite laminates with metals or metal alloys. As such, the present
techniques may include drilling fluid combined with various compressible
particles
(i.e. mixing hollow objects that collapse at different pressures) configured
to maintain
the mud weight or density between the FG and PPG.
[0028] Turning now to the drawings, and referring initially to FIG. 1, an
exemplary drilling system 100 in accordance with certain aspects of the
present
techniques is illustrated. In the exemplary drilling system 100, a drilling
rig 102 is
utilized to drill a well 104. The well 104 may penetrate the surface 106 of
the Earth
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to reach the subsurface formation 108. As may be appreciated, the subsurface
formation 108 may include various layers of rock (not shown) that may or may
not
include hydrocarbons, such as oil and gas, and may be referred to as zones or
intervals. As such, the well 104 may provide fluid flow paths between the
subsurface
formation 108 and production facilities (not shown) located at the surface
106. The
production facilities may process the hydrocarbons and transport the
hydrocarbons
to consumers. However, it should be noted that the drilling system 100 is
illustrated
for exemplary purposes and the present techniques may be useful in accessing
and
producing fluids from any subsurface location, which may be located on land or
water. The well 104 although shown as vertical may be a deviated or
horizontal.
[0029] To access the subsurface formation 108, the drilling system 100 may
include drilling components, such as bottom hole assembly (BHA) 110, drill
pipe 112,
casing strings 114 and 115, parasite strings 122, drilling mud processing unit
116 for
processing the variable density drilling mud 118 and other systems to manage
drilling and production operations. The BHA 110 may include a drill bit, bit
nozzles,
separators and other components that are utilized to excavate the formation,
cement
the casing strings, separate compressible particles from the variable density
drilling
mud 118 or perform other drilling operations within the welibore. The casing
strings
114 and 115 may provide support and stability for access to the subsurface
formation 108, which may include a surface casing string 115 having a casing
shoe
121 and one or more intermediate or production casing strings 114 having a
casing
shoe 119. The production casing string 114 may extend down to a depth near the
subsurface formation 108 with an open hole section 120 extending from the
casing
shoe 119 through the subsurface formation 108. The parasite strings 122 may
provide an alternative flow path through a portion of the well 104 to provide
compressible particles of the variable density drilling mud 118 to specific
locations.
The parasite string 122, which is shown in the annulus between the casing
strings
114 and 115, may also be disposed within the casing string 114. The drilling
mud
processing unit 116 is utilized to manage the slurry (i.e. variable density
drilling mud
118 and cuttings) from the wellbore and provide the formulated variable
density
drilling mud 118 to the wellbore for drilling operations. The drilling fluids
processing
unit 116 may include pumps, hydrocyclones, separators, screens, mud pits,
shale
shakers, desanders, desilters, centrifuges and the like.
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[0030j During the drilling operations, the use of a variable density drilling
mud 118 as a drilling mud allows the operator to drill deeper below the
surface 106
with longer uncased intervals, maintain sufficient hydrostatic pressure,
prevent an
influx of formation fluid (gas or liquid), and remain below the FG that the
formation
can support. The BHA 110 and drilling mud processing unit 116 may be utilized
to
manage the compressible particles in the variable density drilling mud 118.
That is,
the BHA 110 and drilling mud processing unit 116 may remove, circulate and
reinsert
the compressible particles within the variable density drilling mud 118 to
enhance the
drilling operations. Accordingly, a method for managing the variable density
drilling
mud 118 is discussed further below in FIG. 2.
[0031] FIG. 2 is an exemplary flow chart for operating the drilling system 100
of FIG. I in accordance with certain aspects of the present techniques. This
flow
chart, which is referred to by reference numeral 200, may be best understood
by
concurrently viewing FIG. 1. In this flow chart 200, a process may be utilized
to
enhance the drilling operations by utilizing compressible particles as part of
a
variable derisity drilling mud 118. This process may enhance the drilling
operations
by managing the compressible particles utilized to form the variable density
drilling
mud. Accordingly, drilling operations performed in the described manner may
reduce inefficiencies by eliminating or reducing additional casing strings
from drilling
operations.
[0032] The flow chart begins at block 202. At block 204, the FG and PPG for
a well may be determined. For example, the PPG may be determined from prior
drilling, taking a kick, evidence of connection gas, downhole tool, or
modeling. The
FG may be determined from leak-off tests, evidence of lost returns and/or
modeling.
Then, a drilling fluid may be selected with certain compressible particles, as
shown in
block 206. The selection of the drilling fluid and compressible particles may
be
based upon International Patent Application No. WO 2006/007347. For instance,
the
selection of drilling fluid and compressible particles may include
compressible (or
collapsible) hollow or at least partially foam filled objects made of polymer,
polymer
composites, metals, metal alloys, and/or polymer or polymer composite
laminates
with metals or metal alloys. The drilling fluid may be tailored to have
certain
properties based on the specific well application.
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[0033] Once the variable density drilling mud (i.e. drilling fluid and
compressible particles) is selected, the drilling operations may be performed
in
blocks 208-212. In block 208, the drilling fluid with the compressible
particles may
be obtained. The drilling fluid and compressible materials may be shipped to
the
drilling location blended together or separately. At block 210, the drilling
fluid and
the compressible particles may be circulated within the wellbore. The drilling
fluid
and compressible particles are configured to maintain the drilling fluid
weight
between the FG and PPG, as discussed above. Then, the compressible particles
may be separated from the drilling fluid at the bottom hole assembly 110, as
shown
in block 212. In particular, the compressible particles may be removed prior
to
reaching the bit nozzles or drill bit to reduce potential damage to the
compressible
particles. The separation of the compressible particles may be performed at
various
locations above the drill bit, which is part of the bottom hole assembly 110.
The
separation may occur directly above the drill bit or at any location along the
BHA
110. That is, the compressible particles of different densities may be
separated from
the drilling mud at various locations. To shunt the compressible particles
around the
drill bit, a separator, such as an in-line centrifugal separator or other
equipment, may
be utilized, as discussed further below with reference to FIGs. 5A-5B.
[0034] In blocks 214-220, the compressible particles may be further
processed to separate, examine and reinsert the compressible particles into
the
drilling fluid for further drilling operations_ At block 214, the compressible
particles
may be separated from the variable density drilling mud 118 and cuttings,
which may
be referred to as slurry. The process of removing the compressible particles
from
the variable density drilling mud, which may be performed at the surface, may
include the use of a centrifuge or other active separation methods and/or a
settling
tank or other passive separation methods, which are part of the drilling mud
processing unit 116. These various methods are discussed further below in FIG.
3A-
3D. At block 216, the damaged compressible particles are removed. The removal
of
damaged or failed compressible particles may include shaker screens, settling
tanks,
hydrocyclones, centrifuges and the like. Then, a determination is made whether
the
drilling operations are complete in block 218. If the drilling operations are
not
complete, the compressible particles may be reinserted into the drilling fluid
in block
220. The methods for reinserting compressible particles into the drilling
fluid may
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include aggressive re-mixing in mud pits after separation and cleanup; venturi
at the
mud pump inlet to induct compressible particles into the drilling fluid;
direct injection
using specially designed pumps; a parasite string to introduce compressible
particles
downhole and/or a dual wailed drill string to introduce compressible particles
as a
slurry just above the drill bit. Each of the methods is discussed further
below in
FIGs. 4A-4E.
[0035] However, if the drilling operations are complete, the hydrocarbons
may be produced from the well 102 in block 222. The production of hydrocarbons
may include completing the wellbore, installing devices within the wellbore
along with
a production tubing string, obtaining the hydrocarbons from the subsurface
reservoir,
processing the hydrocarbons at a surface facility and/or other similar
operations.
Regardless, the process ends at block 224.
Methods of Surface Separation of Compressible Particles from the Variable
Density
Drilling Mud:
[0036] As discussed above in block 214, several methods may be utilized to
separate compressible particles, such as solid or hollow objects, from the
variable
density drilling mud 118 at the surface 106. Typically, the drilling mud
processing
units 116 may include basic surface mud cleaning equipment located on drilling
rigs,
such as scalpers, shale shakers to remove formation cuttings from the flow
path
based on their size, desanders, desilters and centrifuges for separating
particles out
of the drilling mud by differences in weight/density. Accordingly, this type
of
equipment may be utilized to separate the compressible particles and the
drilling fluid
based on the properties of the specific compressible particles, which may be
positively or negatively buoyant. For instance, if the compressible particles
are in the
uncompressed state, the compressible particles, which may include a gas and
gas
impermeable membrane, may have a density that is less than the drilling fluid
and
cuttings in the slurry. Therefore, the compressible particles are positively
buoyant
and naturally float to the surface of the slurry. The buoyancy force counters
the
viscous properties of the slurry and/or the interaction of multiple
uncompressed
compressible particies.
[0037] Accordingly, various different embodiments may be utilized as part of
the drilling mud processing units 116, which are shown in FIGs. 3A-3D. In a
first
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embodiment, a compressible particles recovery unit 300 may be part of the
drilling
mud processing units 116 and used to isolate the compressible particles from
the
slurry, which is shown in FIG. 3A. The compressible particles recovery unit
300 may
include one or more shaker screens 302, 304 and 308 and one or more
hydrocyclones 306. In particular, the compressible particles recovery unit 300
may
be a Drill Bead Recovery Unit from Alpine Mud Products with various
modifications
based on the compressible particles, which may include optimizing screen
sizing and
the hydrocyclone's operation. In this compressible particles recovery unit
300, rig
shaker screens 302 are sized to capture material equal to or greater than the
size of
the compressible particles 310, which may also include formation cuttings. The
slurry is divided into a first shaker flow path of material equal to or
greater than the
size of the compressible particles 310 and a second shaker flow path of other
cuttings in the slurry. The'remaining cuttings and compressible particles 310
in the
slurry of the first shaker flow path pass over cutting shaker screens 304 that
pass the
compressible particles 310 through, while rejecting the larger cuttings.
Again,
through the cutting shaker screens 304, the slurry is divided into a first
cutting flow
path of compressible particles 310 and other material equal to or smaller than
the
compressible particles 310 and the second cutting flow path of material
greater than
the size than the compressible particles 310. Then, the compressible particles
310
are concentrated in one or more hydrocyclones 306 because in the uncompressed
state the compressible particles 310 may have low density compared to the
remaining cuttings or liquid drilling mud. The hydrocylones 306 accelerate the
remaining slurry radially and establish a density gradient where the lightest
material
(i.e. compressible particles 310, for example) migrate out of the top of the
hydrocyclone along a first hydrocyclone flow path and the heavier material
migrates
out the bottom into a second hydrocyclone flow path. Accordingly, from the
hydrocyclones 306, the remaining slurry is divided into a first hydrocyclone
flow path
of material having a density similar to the compressible particles 310 and a
second
hydrocyclone flow path of other material having a density different from the
compressible particles 310. For example, the damaged compressible particles
may
be part of the second flow path. The other material may be lighter or heavier
than
the compressible particles depending on the specific application. Finally, the
compressible particles 310 are recovered from the entrained fluid or first
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hydrocyclone flow path via additional shaker screens 308, which separate the
compressible particles from the other material in the remaining slurry.
[0038] In a second embodiment, the compressible particles recovery unit
320, which is part of the drilling mud processing units 116, may include two
or more
rig shaker screens 322 and 326 and settling tanks 324 as shown in FIG. 3B. In
this
embodiment, the slurry from the wellbore passes across primary rig shaker
screens
322 to remove material greater than the size of the compressible particles
310. The
slurry is divided into, a first shaker flow path of material greater than the
size of the
compressible particles 310 and a second shaker flow path of the material equal
to or
smaller than the compressible particles 310 in the slurry. The remaining
slurry
containing cuttings and compressible particles 310 in the second shaker flow
path
are then transferred to one or more settling tanks 324 of sufficient volume to
allow
separation by density. Particle settling is a function of particle size,
particle density,
suspending fluid density and suspending fluid viscosity. The settling time of
the
compressible particles 310 is significantly less than the settling time of any
weighting
agent (e.g. barite or hematite) suspended in the slurry primarily due to their
relative
size. For example, large particles of about 1 mm (millimeter) in diameter with
a
density of 5 ppg (pounds per gallon) in a 15 ppg drilling fluid with a
viscosity of 10
centipoises rise at 0.03 m/sec (meters per second). Small particles of about
50
micron in diameter with a density of about 35 ppg in a 7 ppg drilling fluid
base oil with
a viscosity of 10 centipoises fall at 5 x 104 m/sec. The residence time in the
settling
tanks 324 is long enough to ensure that the compressible particles 310 float
to the
surface. For example, in a 6 foot deep tank, a compressible particle may rise
to the
surface in about 1 minute. It should be noted that this settling time may vary
for
different compressible particles and drilling fluid. Then, the compressible
particles
310 are separated based on the density. For instance, if the compressible
particles
310 are lighter than the cuttings and other material, the compressible
particles may
be skimmed off the top of the settling tank 324 or passed over secondary
shaker
screens 326 to remove them from the slurry along a first settling flow path.
The
other material in the slurry, which may include damaged compressible
particles,
cuttings, or other material having higher density, may be removed through a
bottom
valve or other methods along a second settling flow path. For instance, the
settling
tanks 324 may be designed with hopper style bottoms to be periodically drained
-of
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any cuttings or may include an auger screw configuration to continuously move
high
density material that have settled within the settling tanks 324.
[0039] In an alternative modification to the second embodiment, the
compressible particles recovery unit 320 may separate the compressible
particles
from larger cuttings in the settling tanks. In this alternative embodiment,
the slurry
from the wellbore passes across primary rig shaker screens 322 to remove
material
greater than or equal to the size of the compressible particles 310. The
slurry is
divided into a first shaker flow path of material greater than and equal to
the size of
the compressible particles 310 and a second shaker flow path of the material
smaller
than the compressible particles 310. The cuttings and compressible particles
310 in
the first shaker flow path are then transferred to one or more settling tanks
324 of
sufficient volume to allow separation by density. In particular, if the
compressible
particles 310 are lighter than the cuttings and other material, the
compressible
particles may be skimmed off the top of the settling tank 324 or passed over
secondary shaker screens 326 to remove them from the slurry along a first
settling
flow path. The other material in the slurry, which may include damaged
compressible particles, cuttings, or other material having higher density, may
be
removed through a bottom valve or other methods along a second settling flow
path.
[0040] In a third embodiment, the compressible particles recovery unit 330,
which is part of the drilling mud processing units 116, may include two or
more
shakers screens 332 and 336 and one or more hydrocylones 334, which is shown
in
FIG. 3C. In this embodiment, the slurry from the wellbore passes across the
primary
rig shaker screens 332 to remove material greater than the size of
compressible
particles 310. The slurry is divided into a first shaker flow path of material
greater
than the size of the compressible particles 310 and a second shaker flow path
of
material in the slurry equal to or smaller than the size of the compressible
particles
310. The material retained on the primary rig shaker screens 332 may be
discarded
as cuttings. The remaining slurry with compressible particles 310 in the
second
shaker flow path is transferred to the hydrocylones 334 that accelerate the
remaining
slurry radially and establish a density gradient where the lightest material
(i.e.
compressible particles 310, for example) migrate out of the top of the
hydrocyclone
along a first hydrocyclone flow path and the heavier material migrates out the
bottom
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into a second hydrocyclone flow path. Additional shaker screens 336 are then
used
to remove the compressible particles 310 from the slurry that exits the top of
the
hydrocyclones 334 along the first hydrocyclone flow path.
[0041] In a fourth embodiment, the compressible particles recovery unit 340,
which is part of the drilling mud processing unit 116, may include two or more
shakers screens 342 and 346 and centrifuges 344, which is shown in FIG. 3D. In
this embodiment, the slurry from the wellbore passes across the primary rig
shaker
screens 342 to remove material greater than the size of the compressible
particles
310. The slurry is divided into a first shaker flow path of material greater
than the
size of the compressible particles 310 and a second shaker flow path of
material in
the slurry equal to or smaller than the size of the compressible particles
310. The
remaining slurry with compressible particles 310 in the second shaker flow
path is
then transferred to centrifuges 344. In the centrifuges 344, the compressible
particles 310 are separated from the other material, which may have a higher
or
lower density. For instance, if the compressible particles 310 are lighter
than the
other cuttings, compressible particles 310 migrate with other light density
material
along a first centrifuge flow path and the heavier material migrates along a
second
centrifuge flow path. Then, additional shaker screens 346 are used to remove
the
compressible particles 310 from the first centrifuge flow path.
Methods for Separating Failed or Damaged Compressible Particles from Variable
Density Drilling Mud:
[0042] As discussed above with regard to block 212, several methods may
be utilized to separate damaged or failed compressible particles from the
variable
density drilling mud. It is envisioned that over time, some fraction of the
compressible particles in the variable density drilling mud may rupture or
fail due to
the stresses imposed during drilling operations. The damage may include damage
from interactions between the drill bit and the formation, between rotating
drill pipe
and formation or casing strings, shear forces if the compressible particles
are sent
through drill bit nozzles, rapid compression and shear forces if the
compressible
particles are passed through mud pumps, or cyclic loading of
compression/expansion as the compressible particles circulate through the
wellbore.
Further, if the compressible particles are formulated by sealing a low density
gas
inside an impermeable shell, the sealed gas may be released by mechanical
failure
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into the variable density drilling mud and the shell's higher density is no
longer
buoyant (i.e. tends to sink if the shell material of the compressible
particles is
negatively buoyant). Then, the previously sealed gas may be released from the
variable density drilling mud at the surface, while the shell may settle by
gravity
according to its material density.
[0043] Regardless, the drilling mud processing units 116 may be utilized to
remove these damaged compressible objects. Again, because the density of the
compressible particles may be less than the drilling fluid and cuttings in the
uncompressed state, the undamaged compressible particles are positively
buoyant
and naturally float to the surface of the slurry at atmospheric conditions,
while the
damaged compressible particles have a density equal to that of the shell
material.
As a result, the methods and embodiments described above in FIGs. 3A-3D may be
utilized to segregate the damaged compressible particles from the slurry. In
this
manner, both damaged and undamaged compressible particles are removed using
the shaker screens along with other equipment. That is, the material greater
than or
equal to the size of the compressible particles is initially separated from
the slurry.
Then, the damaged compressible particles and smaller cuttings in the slurry
are
separated by density from the compressible particles based on the various
methods
described above. For instance, in the settiing tank, the undamaged
compressible
particles may float, while the damaged compressible particles may sink. In
this
example, the damaged compressible particles may be disposed of properly with
other cuttings or may be recovered for recycling of the shell material.
Methods for Reinserting Comgressible Obiects into the Drilling fluid stream:
[0044] As discussed above in blocks 208 and 220, several methods may be
utilized to mix or combine the compressible particles with the drilling fluid
to create
the variable density drilling mud 118. Typically, the drilling fluid may be
delivered to
the drilling site fully formulated without compressible particles. This may
reduce the
mud delivery volume and utilize the least number of supply trucks and/or
boats. The
drilling fluid may also be formulated on-site from raw materials. Regardless
of the
method to obtain the compressible particles and drilling fluid, the
compressible
particles may be mixed or combined to create the variable density drilling mud
118
prior to reaching the annulus near the drill bit of the bottom hole assembly
110. That
is, the compressible particles may be introduced for the first time to the
drilling
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operations when switching from a conventional mud to variable density drilling
mud
118 or after the routine solids control operations at the surface. In
addition, the
surface weight or density of the drilling fluid with and without compressible
particles
may be monitored and compressible particles added to achieve the desired
continuous gradient effect downhole.
[0045] Regardless of the method utilized to obtain the drilling fluid with the
compressible particles, the drilling mud processing units 116 may be utilized
to
circulate the compressible particles with the drilling fluid to create the
variable density
drilling mud 118. The drilling mud processing units 116 may include
pumps/mixers
and other equipment to insert and reinsert the compressible particles into the
wellbore or into the drilling fluid, which are shown in FiGs. 4A-4E. For
example, in a
first embodiment shown in FIG. 4A, a compressible particle insertion unit 400
may
mix the compressible particles 410 with the drilling fluid 412. The
compressible
particle insertion unit 400 may include one or more mud pits 402, mixers 404,
inlet
monitors 406 and mud pumps 408. The compressible particles 410 and drilling
fluid
412 are added to the mud pits 402 (i.e. suction pit or earlier) and thoroughly
blended
with mixers 404, such as paddle mixers and jet mixers. The mud density or
weight
of the material, which includes the compressible particles 410 and drilling
fluid 412,
in the mud pit 402 is monitored by inlet monitors 406. The blended material
forms
the variable density drilling mud 118 of FIG. 1 configured to provide the
continuous
gradient behavior within the wellbore. The variable density drilling mud is
provided to
the mud pumps 408, which may be provided at about 1 to 2 or more times the
volumetric flow rate that the mud pumps 408 deliver to the wellbore via the
flow path
409. Typically, the pressure at which the compressible particles compress into
a
contracted state may be exceeded by the mud pumps 408. Depending on total mud
compressibility, the mud pumps 408 deliver the variable density drilling mud
at a
volumetric flow rate less than or equal to the intake volumetric flow rate for
the mud
pumps.
[0046] In a second embodiment, the compressible particles 410 may be
blended with the drilling fluid in the monitors, as shown in FIG. 4B. In this
embodiment, the compressible particle insertion unit 420 may include one or
more
mud pits 422, monitors 424 and mud pumps 426. The drilling fluid 412 is added
to
the mud pits 402 (i.e. suction pit or earlier). Then, the compressible
particles 410
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may be metered by monitors 424 that manage the amount of compressible
particles
410 provided into the flow path 428 before entering the mud pumps 426. With
this
method, the compressible particles 410 may be introduced in a dry form or as
concentrated slurry via a venturi. Again, the mud pumps 408 deliver the
variable
density drilling mud at a volumetric flow rate less than or equal to the
intake
volumetric flow rate of the mud pumps. The compressible particles 410 and the
drill
fluid 412 are combined for delivery to the wellbore via the flow path 428.
[0047] In a third embodiment, a dedicated pump or pump set may be used to
apply pressure to concentrated compressible particle-mud slurry so that the
particles
are nearly fully compressed, as shown in FIG. 4C. The dedicated pump may be
beneficial when the surface circulating pressure is enough to place the
compressible
particles into a compressed state prior to injection into the wellbore. In
this
embodiment, the compressible particle insertion unit 430 may include one or
more
storage vessels 432, compression pumps 434, piping 436 and rig pumps 438. The
compressible particles 410 and drilling fluid 412 are combined in the storage
vessel
432, which may be a mud pit or specific vessel. Then, the compression pumps
434
compress the variable density drilling mud from the storage vessel 432. The
compressed variable density drilling mud, which includes the drilling fluid
412 and
compressible particles 410, is introduced either upstream or downstream of the
main
rig pumps 438 through piping 436, which includes a series of check valves and
manifolds to prevent backfiow. This configuration reduces the amount of work
provided by the main rig pumps 438 to compress the variable density drilling
mud.
[0048] In a fourth embodiment, the drilling fluid and compressible particles
410 are isolated until reaching the annulus in the wellbore near the drill
bit, as shown
in FIG. 4D_ Because the continuous gradient or variable density behavior is
utilized
in the annulus of the wel)bore, the compressible particles may be mixed with
the
drilling fluid within the wellbore annulus. In this embodiment, the
compressible
particle insertion unit 450 may include one or more drilling fluid pumps 452,
compressible particles pumps 454, drill bit 456, and dual-walled drili- pipe
string
having an inner pipe and an outer pipe that create a primary flow path 458 and
a
secondary flow path 460. With the dual-walled drill pipe string, a first
fluid, such as
the drilling fluid 412, is pumped down the primary flow path 458, which is
within the
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inner pipe by the drilling fluid pumps 452. The second fluid, such as the
compressible particles 410 with some portion of drilling fluid, is pumped down
the
second flow path 460, which is the annulus between the inner pipe and outer
pipe,
by the compressible particles pumps 454. The drilling fluid 412 passes through
the
drill bit 456 and is circulated to a blending section 464 located above the
drill bit 456,
while the compressible particles 410 exit directly into the blending section
464. The
volumetric flow rate of the individual fluids is preferably controlled to
provide the
desired concentration of compressible particles 410 in a blending section 464,
which
may be the annulus above the drill bit 456.
[0049] In a fifth embodiment, the drilling fluid and compressible particles
410
are isolated until reaching an injection port on a parasite pipe, as shown in
FIG. 4E.
Because the continuous gradient or variable density behavior is utilized in
the
annulus of the wellbore, the compressible particles are mixed with the
drilling fluid
412 at an injection port. In this embodiment, the compressible particle
insertion unit
470 may include one or more drilling fluid pumps 472, compressible particles
pumps
474, drill bit 476, drill pipe 478, such as drill pipe 112, and a parasite
string 480, such
as parasite string 122. With this configuration, a first fluid, such as the
drilling fluid
412, is pumped down the drill pipe 478 by the drilling fluid pumps 472, while
the
second fluid, such as the compressible particles 410, is pumped down the
parasite
string 480 by the compressible particles pumps 474. The drilling fluid 412
passes
through the drill bit 476 and is circulated to a blending section 482 located
above the
drill bit 476, while the compressible particles 410 exit directly into the
blending
section 482 from the outlet of the parasite string 480. The volumetric flow
rate of the
individual fluids is controlled to provide the desired concentration of
compressible
particles 410 in a blending section 482, which may be the annulus of the well
near
the casing string 114 or the drilt bit 476.
[0050] As a specific example, a drilling system may utilize a variable density
drilling mud that is a mixture of drilling fluid with a density of 15 pounds
per gallon
(ppg) and compressible particles having a uncompressed state density of 4.8
ppg
with the compressible particles configured to compress above 1500 pounds per
square inch (psi). Referring to FIG. 1, these particles may be injected into
the
wellbore via the parasite string 122 with the compressible particles being 40
% of the
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volume of the variable density drilling mud 118 when in the uncompressed
state.
Below the injection port, no compressible particles are present and the mud
may
have a density of 15 ppg. Above the injection port, the density of the
variable density
drilling mud may adjust based on the expansion of the compressible particles.
Above the depth where the annular pressure is less than 1500 psi, the variable
density drilling mud has constant density because the compressible particles
have
expanded to the uncompressed state. Accordingly, the density of the variable
density drilling mud may be tailored by adjusting the collapse pressure of the
compressible particles, the number of compressible particles and the drilling
fluid
density.
[0051] Beneficially, the present techniques reduce or prevent damage to the
compressible particles. In addition, the present technique may be utilized to
manage
well control issues, such as kicks and underground flow. For instance, a well
control
event may occur in a well. To manage the well control event, the flow of
compressible particles from the parasite string 122 may be instantaneously
stopped
from the surface. In this manner, only compressible particles within the
wellbore
above the injection point are present within the well, while the drill pipe
contains
regular mud, i.e., without compressible particles. The compressible particles
contained in the wellbore above the injection point may be circulated back to
the
surface by injecting mud with higher or lower density through the parasite
string,
while the drill pipe is shut. This technique allows well control issues to be
resolved in
a manner that is easier to implement than by circulating drilling mud through
the drill
pipe.
Method for Separation of the Compressible Particles Downhole:
[0052] As discussed above in block 212, the compressible particles may be
separated within the wellbore to reduce potentially negative impact of high
shear on
the compressible particles. For example, the compressible particles may be
isolated
from the flow path inside the drill pipe 112 and directed to the annulus above
the
bottom hole assembly 110. Removing the compressible particles from the flow
path
inside the drill pipe 112 may avoid high shear regions in and around the bit
nozzles
and prevent the compressible particles from undergoing additional mechanical
deformation and wear. Further, it may also keep the compressible particles
away
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from potentially destructive downhole mud motors or turbines that are driven
by fluid
flow.
[0053] The removal of compressible particles may be adjusted based on the
density of compressible particles relative to the drilling fluid. For
instance, as shown
in FIG. 5A, if the drilling fluid is heavier than the compressible particles,
the
compressible particles may be separated in a downhole separator 500. The
downhole separator 500, which is a part of the bottom-hole assembly (BHA) 110,
may be utilized within the wellbore to divert or separate the compressible
particles
from the variable density drilling mud 118. The downhole separator 500 may be
a
centrifugal separator or hydrocyclone that is located above the drill bit 502
and
attached to the drill pipe 112. The separator 500 may include a flow diverter
504, a
main chamber 505 and a bypass tube 506.
[0054] Similar to hydrocyclones used for separating compressible particles at
the surface, a downhole separator 500 may be placed above other BHA components
to accelerate the variable density drilling mud 118 from the drill pipe 112 in
a circular
or spiral fashion to induce centrifugal acceleration, as shown by solid line
508. As
the variable density drilling mud 118 is accelerated, the heavier mud
components
migrate to the outside wall of the main chamber 505 and exit through a bit
nozzle
503, as shown by dotted line 512. The lighter drilling mud components migrate
to
the middle or center of the main chamber 505 and enter into the bypass tube
506, as
shown by dashed line 510. Even in a compressed state, the density of the
compressible particles may be less than that of the drilling fluid. As such,
the middle
portion of the flow path containing the highest concentration of compressible
particles is diverted to the wellbore annulus through an opening in the
downhole
separator, which is the bypass tube 506, while other remaining fluid flow is
diverted
toward the drill bit 502. The fluid from these flow paths is then mixed with
the
annular fluid above the drill bit 502 to achieve the variable density drilling
mud 118.
[0055] In an alternative embodiment, as shown in FIG. 5B, if the
compressible particles in the compressed state are heavier than the drilling
fluid, the
flow paths may be altered to form a different separator 520. In this separator
520,
which may again be located above the drill bit 502, the flow diverter 522 and
main
chamber 524 may function similar to the discussion above. However, the bypass
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tube 526 may divert heavier material, such as the compressible particles, in
the
variable density drilling mud 118 into the annulus from an outside wall of the
main
chamber 524. Again, the downhole separator 520 may be placed above other BHA
components to accelerate the variable density drilling mud 118 from the drill
pipe 112
in a circular or spiral fashion to induce centrifugal acceleration, as shown
by solid line
528. As the variable density drilling mud 118 is accelerated, the heavier
components, such as the compressible particles in the compressed state,
migrate to
the outside wall of the main chamber 524, as shown by dashed line 530. The
lighter
materials, which may be the drilling fluid, migrate to the middle of the main
chamber
524 and flow out the main chamber 524 through the bit nozzle 503, as shown by
dotted line 532. Near the bottom of the downhole separator 520, the outer
portion of
the fluid flow near the wall of the main chamber 524 contains the highest
concentration of compressible particles and is diverted to the welibore
annulus
through an opening in the downhole separator, which is the bypass tube 526.
The
fluid from these flows is then mixed with the annular fluid above the drill
bit 502 to
achieve the variable density drilling mud 118.
[0056] Further, it should be noted that equipment at the surface of the
drilling
operations may be sized for larger volumetric flows than equipment associated
with
the downhole portions of the well. For instance, the inlet flow rate for the
mud pumps
at the surface of the wellbore may be larger than the flow rates for the BHA
110
because the compressed particles in the compressed state occupy less volume.
That is, the flow rate of equipment within the wellbore may be substantially
less than
the flow rate of pumps at the surface because the compressible particles are
in the
compressed state. While this flow rate reduction may reduce hole cleaning
functions
of the variable density drilling mud 118, the size of the downhole equipment
may be
reduced to further reduce costs.
[0057] In addition, it should be noted that these various exemplary
applications may be modified to address specific configurations of the
compressible
particles based on the density of the compressible particles. For instance, as
noted
above, the other material in the variable density drilling mud 118 may be
lighter or
heavier than the compressible particles depending on the specific application.
At the
surface, the compressible particles may tend to be in the expanded or
uncompressed state. As a result, the compressible particles may be lighter
than the
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other material in the variable density drilling mud 118, and may be removed as
noted
above. However, the drilling mud processing unit 116 may also be modified to
remove compressible particles for any range of densities. Similarly, in the
downhole
sections of the wellbore, the compressible particles are typically in the
compressed
state. In these downhole intervals, the compressible particles may be lighter
or
heavier than other material in the variable density drilling mud 118. As such,
the
downhole separator may be configured in a variety of embodiments to separate
the
compressible particles based on the density of the compressible particles.
[0058] Moreover, it should also be noted that the compressible particles may
include one, two, three or more types of compressible particles that have
different
characteristics, such as shapes, density and size. Again, the specific
configuration
of the drilling mud processing unit 116 and downhole separators 500 and 520
may
be modified to manage these differences. For example, with regard to the
drilling
mud processing unit 116, the embodiments described above may manage the
separation of the compressible particles having different characteristics.
However,
the drilling mud processing unit 116 may be modified to have a series of two
or more
shaker screens 302, 304, 308, 322, 326, 332, 336, 342 and 346 utilized with a
series
of one or more hydrocyclones 306 and 334 or centrifuges 344 that are
configured to
separate the different compressible particles from the flow paths. These
adjustments may provide additional flow paths for the different sizes or
densities of
the compressible particles.
[0059] As a specific example of separation on the surface, the compressible
particles recovery unit 330 may include the shaker screens 332 having a first
primary
shaker screen and a second primary shaker screen and hydrocyclones 334 having
a
primary and secondary hydrocyclones. In this embodiment, the first
compressible
particles are greater in size than the second compressible particles. The
slurry from
the wellbore passes across the first primary rig shaker screen to remove
material
greater than the size of a first compressible particles 310. The slurry is
divided into a
first primary shaker flow path of material greater than the size of the first
compressible particles 310 and a second shaker flow path of material in the
slurry
equal to or smaller than the size of the first compressible particles. The
material
retained on the primary rig shaker screens may be discarded as cuttings. The
remaining slurry with compressible particles in the second primary shaker flow
path
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passes across the second primary rig shaker screen to remove material greater
than
the size of the second compressible particles. The slurry is divided into a
third
primary shaker flow path of material greater than the size of the second
compressible particles and a fourth primary shaker flow path of material in
the slurry
equal to or smaller than the size of the second compressible particles. The
material
on the third primary shaker flow path is transferred to a primary hydrocylone
that
separates the first compressible particles from other material to migrate out
of the
top of the primary hydrocyclone along a first primary hydrocyclone flow path
and the
heavier material migrates out the bottom into a second primary hydrocyclone
flow
path. The material on the fourth primary shaker flow path is transferred to
the
secondary hydrocylone that separates the second compressible particles from
other
material to migrate out of the top of the secondary hydrocyclone along a first
secondary hydrocyclone flow path and the heavier material migrates out the
bottom
into a second secondary hydrocyclone flow path_ Additional shaker screens may
then be used to remove the compressible particles from the slurry that exits
the top
of the hydrocyclones, which may be sized for the first or second compressible
particles.
[0060] As a specific example of separation within the wellbore, the downhole
separator 500 and 520 may be utilized to separate the compressible particles
having
different characteristics in a single downhole separator. However, other
embodiments may include a series of downhole separators utilized to separate
the
individual compressible particles. For instance, two or more downhole
separators
may be utilized to remove the compressible particles in a two-stage process
depending on the density of the compressible particles. For instance, if the
first
compressible particles in the compressed state are heavier than the drilling
fluid and
the second compressible particles are lighter in the compressed state than the
drilling fluid, the downhole separator 500 may be coupled to the downhole
separator
520 in series to remove the compressible particles at the different stages.
Other
embodiments may also be considered within the scope of this description of the
embodiments.
[0061] In addition, the downhole separators 500 and 520 may be utilized at
various locations within the wellbore to further manage the density profile
within the
wellbore annulus. For example, as shown in FIG. 6, the drilling system 600 may
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include drilling components, such as bottom hole assembly (BHA) 110, drill
pipe 112,
casing strings 114 and 115, parasite strings 122, drilling mud processing unit
116 for
processing the variable density drilling mud 118, downhole separators 602a-
602n,
and other systems to manage drilling and production operations. Because some
of'
the components in the drilling system 600 are similar to the components of the
drilling system 100, the same reference numerals are utilized. In this
drilling system
600, the downhole separators 602a-602n, which may be embodiments of the
downhole separators 500 and 520, may be coupled to the sections of drill pipe
112 to
manage the density within the wellbore annulus. Also, it should be noted that
the
downhole separators 602a-602n may include any number of downhole separators,
such as one, two, three or more, based on the desired density profile for the
wellbore.
[0062] In the drilling system 600, the well 104 may penetrate the surface 106
of the Earth to reach the subsurface formation 108. The downhole separators
602a-
602n may be placed within the well 104 at various places to control the
density
profile by removing a portion of the compressible particles the variable
density drilling
mud 118. The downhole separators 602a-602n may include any number of
downhole separators, such as one, two, three or more, based on the desired
density
profile for the wellbore. A mixture of compressible particles having different
densities
may be used in the drilling process. Each separator is designed to separate a
significant fraction of compressible particles, which may be adjusted based on
the
density designed for the wellbore, with a certain density from the flow inside
the drill
pipe and direct out of the drill pipe and into the wellbore annulus. For
example, the
drilling fluid may contain three types of compressible particles, which each
having a
different density profile versus pressure from the others. The lowest internal
pressure compressible particles may be separated in the first separator and
directed
to the wellbore annulus because they have a higher density state. The higher
internal pressure compressible particles may be separated at deeper locations
in the
drill pipe and directed to the wellbore annulus in other downhole separators.
The
highest internal pressure compressible particles may be separated in a
downhole
separator that is part of the BHA and directed to the wellbore annulus near
the drill
bit. As such, the downhole separators 602a-602n provide additional flexibility
in
managing the compressible particles and density profiles of the wellbore.
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[0063] Also, it should be noted that the different methods and processes for
removing the compressible particles may not remove all of the compressible
particles, but may remove either a specific portion or a substantial amount of
,
compressible particles. For instance, with the downhole separators, the
separators
may remove a substantial amount, such as 70 %, of the compressible particles
from
the variable density drilling mud. The efficiency of the separations may be
based on
the downhole environment, downhole geometry and other factors, which may be
specific to the application. As such, the various devices described above may
remove at least a portion or all of the compressible particles, which may vary
with
different configurations.
[0064] Moreover, in other alternative embodiments, monitors may be used to
further enhance the process. For example, as the well is drilled, the
compressible
particles are submitted to forces that may cause the compressible particles to
rupture or fail resulting in a substantial loss of compressibility. Also, over
time, the
internal pressure of the compressible particles may decrease due to shell wall
permeability. That is, while some compressible particles may maintain an
internal
pressure, others may lose internal pressure due to permeability through the
wall of
the compressible particles. These slightly damaged compressible particles may
be
recirculated because they have similar densities to other compressible
particles that
maintain their internal pressure. Thus, it becomes increasingly difficult to
determine
the wellbore density profile in the absence of downhole pressure while
drilling (PWD)
tools.
[0065] To enhance the operation of the system, monitors, such as mud
density and pressure monitors, may be used to predict the downhole density
profile.
The calculation and prediction of the variable density drilling mud density
(or
pressure) profile within the wellbore may be beneficial to prevent exceeding
the FG
or going below the PPG, while drilling to a subsurface formation. Accurate
methods
for predicting the density profile of the variable density drilling mud are
based on an
understanding of the compressibility behavior of the components in the
drilling fluid
system. For example, the density profile at the initial stages of operations
or for
unused compressible particles may be predicted from modeling or experimental
data
and tests because the compressible particle's response to pressure is based on
internal pressure and shell wall compression of the compressible particles. As
such,
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modeling or experimental data may be used to provide the density profiles for
different variable density drilling muds.
[0066] As the drilling operations progress, attrition of the high volume
fraction
of discrete compressible particles contained in the variable density drilling
mud
should be considered. That is, the attrition rate should be used in the
calculation of
bottom hole pressure with compressible drilling mud because it involves the
integration of the variable mud density with depth from the surface to the
bottom of
the well. As a result, an accurate knowledge of the pressure-volume-
temperature
(PVT) characteristics of the variable density drilling mud may be useful to
understand
the compressible particle attrition rates. Accordingly, a method or mechanism
is
needed to measure the physical attrition rate along with any loss of internal
particle
pressure over time experienced by the distribution of compressible particles
in the
variable density drilling mud.
[0067] To provide this functionality, embodiments may continuously monitor
the PVT characteristics of the variable density drilling mud in the wellbore.
This can
be accomplished by instrumenting the reciprocating mud pumps to continuously
measure and record the piston displacement, the internal cylinder pressure as
a
function of piston displacement and the temperature of the mud in the cylinder
during
compression. In this manner, the PVT characteristics of the variable density
drilling
mud being injected into the wellbore is continuously available for the
calculation of
downhole density or pressure profile (particularly in the absence of PWD tools
in the
BHA). In addition, this data can be used to monitor the variable density
drilling mud
characteristics for the purpose of maintaining and/or changing the variable
density
drilling mud properties by addition or replacement of mud components, such as
the
compressible particles or drilling fluid, for example. The monitoring of these
mud
pumps, which may include mud pumps 408 and 426, for example, may provide
additional data on the density to provide the proper density within the
wellbore.
[0068] Accordingly, the use of the monitor may enhance drilling operations.
For example, the monitors may determine the pressure volume temperature (PVT)
characteristics of the variable density drilling mud. The PVT characteristics
may be
used to modify the volume of the compressible particles in the variable
density
drilling mud to provide a desired density and/or to modify the volume or
density of
the drilling fluid in the variable density drilling mud to provide a desired
density.
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Further, PVT characteristics of the variable density drilling mud may be used
to
modify the volume of a first group of compressible particles having a first
internal
pressure and a second group of compressible particles having a second internal
pressure to provide a desired density. That is, in other embodiments, the PVT
characteristics may be used to allocate different volumes for compressible
particles
having different internal pressures to provide a specific density profile.
[0069] An alternative technique may be to have a compression device, which
may operate continuously, to measure the PVT characteristics separate from the
mud pumps. This compression device may take samples directly from the storage
areas, such as mud pits 402 and 422 and/or storage vessel 432. In addition,
there
may be multiple devices measuring the PVT behavior or characteristics for the
variable density drilling mud entering the drill string and the mud exiting
the annulus
of the wellbore.
[0070] Further still, the monitoring of the variable density drilling mud may
also be beneficial in preventing and overcoming; kicks, in the event the
variable
density drilling fluid column pressure goes below the formation pore pressure,
and
fluid loss, in the event the variable density drilling fluid column pressure
exceeds the
formation fracture pressure. For example, a kick is often detected at the
surface by
mud pit volume gain while drilling and circulating the variable density
drilling mud or
annular flow after the mud pumps are turned off. When circulating frictional
pressure
is removed from the variable density drilling mud and the mud pumps are turned
off,
the compressible particles in the variable density drilling mud are expected
to
expand, and the variable density drilling mud in the welibore annulus may flow
out of
the annulus. For a typical incompressible drilling mud, this may be perceived
as
evidence of taking a kick. Accordingly, understanding the density profile of
the
variable density drilling mud through surface measurements of PVT behavior may
be
beneficial in determining the difference between expansion of the compressible
particles after the mud pumps are turned off and the taking of a kick.
[0071] If it is determined that a kick has been taken, common methods for
overcoming the kick include the driller's method (e.g., two circulation
process that
removes kick with same density variable density drilling mud and then
increases
density of the variable density drilling mud that is circulated into the
wellbore) and the
weight and wait method (e.g., single circulation process that increases
density of the
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variable density drilling mud while maintaining bottom hole pressure and
circulates
the kick out of the wellbore). In both methods, the bottom-hole pressure is
maintained at a substantially constant level, while circulating the kick from
the
welibore. Again, in the absence of a PWD tool in the drill string, it may be
beneficial
to have real-time or near real-time measurements of the density profile of the
variable density drilling mud as a function of pressure. In this manner, the
bottom
hole pressures may be determined given the mud density profile and the surface
pressures applied to the drill string or annulus during the kick circulation
procedures.
[0072] While the present invention may be susceptible to various
modifications and alternative forms, the exemplary embodiments discussed above
have been shown only by way of example. The embodiments described above are
not intended to include all possible configurations of the various separation
equipment and techniques (e.g., shakers, hydrocyclones, settling tanks,
centrifuges,
and the like). It is envisioned that any of the separation techniques
described above
may be combined in such a way to achieve the desired separation of
compressible
particles from the variable density drilling mud or from other compressible
particles
by size and density. Again, it should be understood that the invention is not
intended
to be limited to the particular embodiments disclosed herein. Indeed, the
present
invention includes all alternatives, modifications, and equivalents falling
within the
true spirit and scope of the invention as defined by the following appended
claims.
